With increasing global demand for oil and its byproducts, extracting oil from geological formations that are increasingly more difficult to reach has become necessary. One remaining source of petroleum are the heavy oils. In fact, the reserves of heavy oil in the world are more than twice those of conventional light crude oil.
Heavy crude oil or extra heavy crude oil is any type of crude oil that does not flow easily. It is referred to as “heavy” because its density or specific gravity is higher than that of light crude oil. Heavy crude oil has been defined as any liquid petroleum with an API gravity less than 20°. Extra heavy oil is defined with API gravity below 10.0° API (i.e. with density greater than 1000 kg/m3 or, equivalently, a specific gravity greater than 1).
The production of heavy oil and bitumen from subsurface reservoirs such as oil sands or shale oil is challenging, and the main reason for the difficulty is the extreme viscosity of the heavy oil or bitumen in the reservoir. At reservoir temperatures, the initial viscosity of the oil is often greater than one million centipoises, which is difficult to produce if not first mobilized using external heat and/or solvent. Therefore, the removal of oil from the reservoir is typically achieved by introducing sufficient energy into the reservoir to heat the reservoir, such that the viscosity of the oil is reduced sufficiently to facilitate mobilization and production, or by injecting solvents to thin the oil, or by combinations thereof. Heat can be added in a number of ways, including injecting steam into the reservoir, in situ combustion or electric or electromagnetic heating methods. Solvent can be added by gas or liquid injections.
Gas reinjection is presently a commonly used approach to enhance recovery. There are two major types of gas injection—miscible gas injection and immiscible gas injection. In miscible gas injection, the gas is injected at or above minimum miscibility pressure (MMP), which causes the gas to be miscible in the oil, thus thinning it. In immiscible gas injection, by contrast, flooding by the gas is conducted below MMP. This low pressure injection of gas is used to maintain reservoir pressure to prevent production cut-off and thereby increase the rate of production.
Low pressure immiscible techniques can be categorized as follows:
Gas Pressure Drive:
Gas or other fluid can be injected into the formation merely to maintain the pressure drive. This traditional step for increasing oil recovery involves the injection of fluid into (or near) an oil reservoir for the purpose of delaying the pressure decline during oil production. Pressure maintenance can significantly increase the amount of economically recoverable oil over that to be expected with no pressure maintenance.
Gas Cap Drive:
a common variation on gas drive pressure support processes, wherein an upper “cap” of gas maintains pressure while oil gravity drains to lower production wells.
High pressure miscible injection processes can be broken down into the following techniques:
Liquefied Petroleum Gas Miscible Slug.
Displacement by miscible slug usually refers to the injection of some liquid solvent that is miscible upon first contact with the resident crude oil. In particular, this process uses a slug of propane or other liquefied petroleum gas (2 to 5% pore volume or “PV”) tailed by natural gas, inert gas, and/or water. Thus, the solvent will bank oil and water ahead of it and fully displace all contacted oil.
Enriched Gas Miscible Process.
In the enriched gas process, a slug of methane enriched with ethane, propane, or butane (10 to 20% PV) and tailed by lean gas and/or water is injected into the reservoir. When the injected gas contacts virgin reservoir oil, the enriching components are slaked from the injected gas and absorbed into the oil.
High Pressure Lean Gas Miscible Process.
This process involves the continuous injection of high pressure methane, ethane, nitrogen, or flue gas into the reservoir. The lean gas process, similar to enriched gas, involves multiple contacts between reservoir oil and lean gas before forming a miscible bank. But, there is a difference in the enriched gas process where light components condense out of the injected gas and into the oil, then intermediate hydrocarbon fractions (C2 to C6) are stripped from the oil into the lean gas phase.
Gases that are used in these various gas injection techniques include CO2, natural gas, nitrogen, ethane, butane, propane, flue gas and the like. Air is usually not used to repressurize conventional reservoirs because of the possibility of fire, but can be used to flood oil sands due to the low temperature of the formation and slow burning nature of the bitumen, although gas injectivity must first be established as the bitumen and other heavy oils are too viscous for gas injection methods.
Oil displacement by carbon dioxide injection relies, in part, on the phase behavior of the mixtures of the gas and the crude, which are strongly dependent on reservoir temperature, pressure and crude oil composition. These mechanisms range from oil swelling and viscosity reduction for injection of immiscible fluids (at low pressures) to completely miscible displacement in high-pressure applications. In these high pressure applications, more than half and up to two-thirds of the injected CO2 returns with the produced oil and is usually re-injected into the reservoir to minimize operating costs. The remainder is trapped in the oil reservoir by various means.
Nitrogen has also been successfully used as the injection fluid for EOR and widely used in oil field operations for gas cycling, reservoir pressure maintenance, and gas lift. The costs and limitations on the availability of natural gas and CO2 have made nitrogen an economic alternative for oil recovery by miscible gas displacement. Nitrogen is usually cheaper than CO2 or a hydrocarbon derived gas for displacement in EOR applications and has the added benefit of being non-corrosive. On the other hand, in some cases methane and CO2 are readily available, and the use of CO2 also allows the possibility of reducing the carbon footprint and/or allowing carbon sequestration. Thus, the choice of gases used will vary based on economics and ecological impact, as well as on reservoir conditions.
The concept of injecting gas into a formation to stimulate recovery of residual oil is therefore not new. Successful laboratory gas-injection experiments generated a lot of optimism in the 1950s, but by the 1970s field experiments yielded only moderate recoveries of 5% to 10% of the remaining original oil in place (OOIP) after the initial drive mechanisms had been exhausted. Viscous fingering, solvent channeling, and reservoir heterogeneity were found to be the main culprits for disappointing field performances.
Electromagnetic energy has also been used in various industries for a number of years, including in enhanced oil recovery techniques. Applications can be divided into two or three categories based on the frequency of the electrical current used in downhole mobilization techniques. The first is low frequency heating and the second is high frequency, and each is discussed in turn.
Low frequency currents (less than 60 Hz) are used in electric resistive heating or “ERH.” In ERH mode it is assumed that resistance heating dominates the process and other factors are negligible. Here the depth of penetration is high, but the intensity low. Low-frequency heating is limited by water vaporization near the wellbore, which breaks the conductive path to the reservoir, and limits the heating rate as well as the resulting production rates.
In high frequency heating, herein called EM heating or EMH, currents are used in microwave (MW) or radio frequency (RF) frequency range. In this high frequency range, dielectric heating prevails, and the dipoles formed by the molecules tend to align with the electric field. The alternation of this field induces a rotational movement on the dipoles, with a velocity proportional to the frequency of alternation. In this instance, heating is produced by the absorption of electromagnetic energy by the polar molecules in the formation; hence, the amount of heat absorbed will depend on the adsorption coefficient of the medium.
EM heating is relatively independent of the thermal conductivity of the oil sand and reservoir heterogeneity. EM heating does not require a heat transporting fluid such as steam or a hot fluid injection process, which avoids the complications associated with generating and transporting a heated fluid, and allows it to be applied in wells with low incipient injectivity. EM heating can also apply to situations where generating and injecting steam may be environmentally unacceptable. Furthermore, a single well can be used to introduce energy to the formation through a power source as well as to recover produced fluids. Production may occur during or immediately after EM heating if the formation pressure is large enough. All of the above are only some of the advantages of EM heating as a recovery method for heavy oil reservoirs with respect to the conventional thermal processes.
Another high frequency based method of heating hydrocarbon deposits is inductive heating, where alternating current flowing through a set of conductors induces a magnetic field in the surrounding medium. The variation of the magnetic field, in turn, induces secondary currents, whose circulation in the medium generates heat. However, this method requires the resource to be conducting, and thus may have limited application.
Although its potential was recognized during the late 70's, application of EM energy to mobilize heavy oils has yet to realize its potential. Problems include the high power costs, inefficient delivery of EM waves to the formation, and equipment failures.
Thus, what is needed in the art are improved methods of mobilizing heavy oil, that are more cost effective and have a smaller environmental impact than current methods.